Natural gas often contains excessive quantities of carbon dioxide and/or hydrogen sulfide, collectively known as acid gases. These contaminants make the natural gas unsuitable for consumption. Aqueous amine-based processors are frequently used to remove these contaminants from the natural gas in a process referred to as "gas sweetening."
In the gas sweetening process, after the natural gas stream passes through the aqueous amine solution, chemical reactions take place wherein the natural gas becomes saturated with water. Accordingly, the water must then be removed. Water removal is accomplished using a dehydration system. The most common system used is a dehydration process utilizing triethylene glycol (TEG) as a liquid desiccant.
In addition to carbon dioxide and hydrogen sulfide contaminants, a natural gas stream often contains one or more aromatic hydrocarbons, including benzene, toluene, ethylbenzene, and xylene. These are collectively known as BTEX or BTX. When natural gas is processed in an amine-based gas sweetening process, significant amounts of BTEX are absorbed by the amine. In the gas sweetening process, the amine compounds are regenerated in a recycling process that results in release of the BTEX from the amine compounds. BTEX compounds are regulated pollutants that must be limited at each plant site below certain emission levels. In recent years, amine-based gas sweetening processes have been recognized as significant contributors to BTEX emissions. Several methods for control of BTEX emissions have been developed.
Control of BTEX emissions from an amine-based gas sweetening process is difficult to accomplish. Some processes attempt to remove BTEX from the amine stream prior to amine regeneration. Others attempt to treat the regeneration system exhaust gases to remove the BTEX emissions.
One currently accepted process for BTEX control is to incinerate the exhaust or tail gases from the amine regeneration system. The amine regeneration system essentially purifies the amine compounds by stripping the absorbed contaminants. Thus, the exhaust gases from the amine regeneration system contain not only the acid gases, but also BTEX that was absorbed by the amine in the amine contactor and then stripped by the regeneration process. This incineration of exhaust gases consumes very large amounts of fuel making it an expensive process, and actually increases other contaminants emitted such as carbon dioxide, which is a by-product of the combustion.
Other processes for BTEX emission control include the use of activated carbon filter systems to absorb the BTEX from the amine flow or from the tail gases in the amine regeneration system. The problem with these filter systems is that the saturated carbon filters still must be disposed of as they are saturated with BTEX contaminants. Furthermore, this process does not eliminate the BTEX from processing plant byproducts or emissions, unless the carbon is used as fuel or otherwise processed in yet another contaminant removal system.
In all of these processes, control of BTEX in an amine-base gas sweetening process is not achieved until after the BTEX has been absorbed in the amine stream. These processes used to remove the BTEX have extensive fuel requirements, have increased disposal and handling requirements, or divert part of the processing plants resources for the purpose of stripping BTEX from the rich amine.
One example of a prior art system for removing hydrocarbons from a natural gas stream is shown in U.S. Pat. No. 4,414,004 to Wagner, et al. The invention disclosed therein is a process for removing condensable aliphatic hydrocarbons and acidic gases from a natural gas stream where the stream is initially treated with polyethylene glycol as a solvent in a first absorption stage. The desired portion of the gas stream is drawn off from this first absorption stage and the stream is then treated with additional polyethylene glycol in a superatmospheric pressure environment in a second absorption stage, the acidic gases being completely or partly absorbed. The solvent which is saturated with the condensable aliphatic hydrocarbons obtained in the first absorption stage is then treated with water in an extraction stage to form a hydrocarbon phase containing the condensable aliphatic hydrocarbons and an aqueous ether phase, and then the hydrocarbon phase is separated from the aqueous ether phase. The solvent charged with acidic gases obtained from the second absorption stage is regenerated by expansion and/or stripping in a regeneration stage and the regenerated solvent is recycled to the absorption.
U.S. Pat. No. 5,453,114 to Ebeling discloses a method for drying natural gas and for reducing the emissions of hydrocarbon aromatics (BTEX) by ultimately separating such contaminants and disposing of them in a burner of a reboiler. The primary steps in this method include passing the natural gas stream through an absorber having a liquid desiccant, the desiccant absorbing water and hydrocarbon impurities from the gas and forming a spent desiccant, passing a portion of the treated gas from the absorber through a desiccant stripper vessel, the balance of the treated gas being passed for distribution, heating the spent desiccant and passing it through the desiccant stripper vessel to purge the spent desiccant of hydrocarbon aromatics, conducting the spent desiccant from the stripper vessel into a reboiler to again heat the spent desiccant, and finally conveying treated gas from the stripper vessel through a burner in a reboiler where the treated gas is combusted with air.
U.S. Pat. No. 5,490,873 to Behrens, et al. discloses a process for hydrocarbon emission reduction which includes the steps of contacting a natural gas stream in a contacting zone with glycol to produce a water rich glycol stream and a dried gaseous product. The rich glycol is heated in a glycol regeneration zone to a temperature below glycol decomposition temperature to produce (i) a water lean glycol for use in contacting additional natural gas in the contacting zone, and (ii) a gaseous, water containing mixture also containing hydrocarbons. Partial condensation of this gaseous mixture provides liquid hydrocarbon, aqueous waste and a gaseous portion that is reintroduced into the contacting zone for contacting, along with additional natural gas feed, with glycol. Ultimately, the hydrocarbon liquids are sent to storage for sale or further separation.
U.S. Pat. No. 5,766,313 to Heath discloses a hydrocarbon recovery system for treating emissions from a glycol reboiler. In short, the emissions from the reboiler are condensed, pressurized and separated so that the hydrocarbon contaminants vapors (such as BTEX) may be directed to a burner used to supply heat to a reboiler.
U.S. Pat. No. 5,084,074 to Beer, et al. discloses a method and apparatus for separating and recovering water and light aromatic hydrocarbons from a gaseous stream. As with the patent mentioned directly above, the recovered hydrocarbons are used to fire a regenerator used in the regeneration of glycol. More specifically, the natural gas stream is contacted with an absorbent (such as glycol) to absorb the water and light aromatic hydrocarbons (BTEX) to produce a water and light hydrocarbon laden stream and a dry gaseous stream. The water and light aromatic hydrocarbon stream is heated in a regenerator to produce a vaporous water and a light aromatic hydrocarbon stream and a lean absorbent for recycle to the contactor. The vaporous water and light aromatic hydrocarbon stream is condensed so that the liquefied light aromatic hydrocarbons are recovered and a separate light gas stream is also recovered for use as fuel gas for the regenerator.
While the foregoing prior art references may be adequate for their intended purposes, none of them disclose the method of this invention, which is explained below in detail.